Report of Investigations No. 132 Continuity and Internal Properties of Gulf Coast Sandstones and their Implications for Geopressured Fluid Production

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Morton, R.A.
Ewing, T.E.
Tyler, N.

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University of Texas at Austin. Bureau of Economic Geology


Continuity of sandstone reservoirs is controlled by various factors, including faults, sand-body geometry, and the distribution of framework grains, matrices, and interstices within the sand body. Except for faults, these factors are largely inherited from the depositional environment and modified during sandstone compaction and cementation. Regional and local continuity of Gulf Coast sandstone reservoirs depends on a four-level depositional and structural hierarchy: (1) genetically related sandstones commonly associated with a single depositional system, (2) areally extensive fault blocks, (3)individual sandstones within a fault block, and (4) isolated reservoirs within a fault-bounded Published and unpublished data on Tertiary and late Quaternary Gulf Coast sandstones of fluvial, deltaic, barrier-strandplain, and submarine channel and fan origins suggest that volumes of sand systems (first hierarchical level) are about 1011 to 1013 ft3, whereas volumes of individual sand bodies are about 109 to 1011 ft3. The continuity and productive limits of ancient sandstones are substantially reduced by faults and internal heterogeneities, which further subdivide sand bodies into individual compartments. In the Wilcox Group and Frio Formation trends of Texas, fault blocks (second hierarchical level) vary greatly in size, most being between 0.3 and 52 mi2); however, the distribution of fault blocks is strongly skewed toward small areas (<I0 mi2). Volumes of individual reservoirs (fourth hierarchical level) determined from engineering production data range from 50 percent less to 200 percent more than volumes estimated by geologic mapping. In general, mapped volumes are less than production volumes for reservoirs in which faults are nonsealing and are greater than production volumes for reservoirs in which laterally continuous shale breaks cause reductions in permeability. Gross variations in the pore properties (porosity and permeability) of a reservoir can be predicted by examining its internal stratification and its sandstone facies if original sedimentological properties are not masked by diagenetic alterations. Six patterns are recognized that describe, in general, the vertical variations in pore properties within a sand body at a well site. Core analyses show (1) upward increases, (2) upward decreases, (3) central increases, (4) central decreases, (5) uniformly low values, and (6) irregular changes in porosity and permeability with depth. Within these trends, porosity and permeability are generally highest in large-scale crossbedded intervals and lowest in contorted, bioturbated intervals and intervals of small-scale ripple cross-laminations. Sandstone facies models and the regional structural fabric of the Gulf Coast Basin both suggest that large and relatively continuous reservoirs should be found where barrier-strandplain and delta-front sandstones parallel regional faults. These conditions should optimize the yield and rate of fluid production from geopressured geothermal aquifers and maximize the efficiency of primary and enhanced recovery of conventional hydrocarbons. Thick fluvial-channel deposits trending roughly normal to regional faults are laterally less continuous than barrier and delta-front sandstones, but they may also be significant targets for exploration and production of unconventional and conventional energy resources


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